This invention relates generally to natural gas wells and more particularly concerns a system and process for reducing the flowing bottom hole pressure of a natural gas well by lowering the surface well head pressure.
The production rate of a natural gas well is a function of the pressure differential between the underground reservoir and the well head. This differential is adversely affected by back pressure against the reservoir pressure. Also, as natural gas and associated liquids are extracted during production, a gradual loss of reservoir pressure occurs in some natural gas wells. Natural gas wells can and do produce liquids, such as water and hydrocarbon. Removal of the produced fluids is dependent upon the velocity of the gas stream and, as the reservoir pressure and flow potential decrease, there is a corresponding drop in the flow velocity of the natural gas through the tubing to the well head. Eventually, when the flowing gas velocity becomes insufficient to overcome the xe2x80x9cfall backxe2x80x9d velocity of the liquids, a column of liquids accumulates in the well bore. The weight of the fluid column above the producing formation causes additional back pressure and a corresponding decrease in natural gas production. The back pressure caused by the liquid column in a typical well is approximately 0.4 psi per column foot.
In order to reduce the back pressure caused by the accumulation of produced fluids in the well bore, several artificial lift technologies have been utilized. In one such technology, commonly referred to as xe2x80x9cplunger lift,xe2x80x9d a plunger acts as an artificial interface between the fluid column and the natural gas. This artificial lift technology utilizes a cyclic well operation with both shut-in and flowing time intervals. During the shut-in cycle of operation, a valve in the flow line is closed in order to increase the reservoir pressure at the well bore. During the subsequent producing cycle, the same valve is then opened to allow the plunger to travel from the base of the tubing to the well head. As the plunger rises, the fluid accumulated above the plunger is delivered to the surface and the hydrostatic pressure against the formation is reduced.
The success of xe2x80x9cplunger liftxe2x80x9d technology is dependent in part upon the comparative values of shut-in bottom hole pressure and flowing surface well head pressure. Well production rates are directly related to the pressure differential available between the shut-in bottom hole pressure and the flowing surface pressure. As the reservoir pressure declines, the significance of the flowing well head pressure increases. Reservoir pressure can decline to the point at which there is insufficient energy available to cause the plunger to travel to the surface against the existing flowing well head pressure. Failure of the plunger to effectively remove accumulated well bore fluids results in a drastic reduction in gas flow rate and even in a cessation of production.
A blow-down or venting method can be utilized to extend the productive life of a gas well in which performance is significantly affected by flowing well head pressure. This method allows the pressurized gas and fluid column present at the end of the shut-in period to flow to the surface ahead of the plunger into a liquid storage tank. Following the plunger arrival, the flow stream of natural gas is redirected through the surface equipment for conditioning and sale. During the blow-down or venting cycle, the natural gas volume above the plunger, together with any pollutants, is lost to the atmosphere. Additional energy is lost in forcing the produced liquids through the surface connections and piping into the storage tanks.
Natural gas production rates on wells equipped with xe2x80x9cplunger liftxe2x80x9d technology vary significantly. Wells are shut in for extended periods of time and, following shut-in, are allowed to produce utilizing the built-up energy or pressure accumulated during the shut-in period. The gas flow rate during the production period is not constant and generally decreases with time following plunger arrival. Natural gas well surface equipment and pipelines also contribute to pressure resistance at the well head. Gas pipelines operate under pressure and can exert a back pressure at the well head in an approximate range of from several pounds per square inch gauge (PSIG) to several hundreds of pounds per square inch gauge (PSIG). Typically, the pressure of the pipeline connection accounts for a significant portion of the producing surface back pressure. In order to reduce the pipeline back pressure on the well head, gas wells have been equipped with well site compression. Well site compression typically allows lowering the pressure of the surface equipment to an operating range of approximately 10 to 30 pounds PSIG, which represents the friction losses through the system and the gas flow stream pressure utilized to operate the equipment. One of the surface equipment functions is to separate liquids from the produced gas using the gas flow stream pressure to transfer recovered fluids to storage tanks. The liquid/gas separation equipment is typically of limited volume and sufficient pressure must be maintained to allow continuous transfer of produced fluids into the storage tanks.
It is, therefore, an object of this invention to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which minimize flowing well head surface pressure, preferably to a pressure approximating zero (0) PSIG. Another object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which uses surface equipment to reduce well head surface pressure. Similarly, it is an object of this invention to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which utilize well site compression, preferably capable of maintaining five (5) PSIG suction pressure or less through the full range of production rates from the well against existing pipeline pressures. It is also an object of this invention to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which have automation and sensing devices capable of responding to fluctuations in gas flow rates. A further object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which are capable of reduced performance during well shut-in periods. Still another object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which allows re-circulation of compressed natural gas. Yet another object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which utilize a liquid/gas sub-normal pressure separation vessel, preferably of sufficient volume to contain produced fluids during the plunger cycle at pressures approaching five (5) PSIG or less. A further object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which employ a mechanism by which produced fluid accumulated in a sub-pressure vessel can be transferred to an existing pressured separation vessel for processing and transfer to storage tanks. It is also an object of this invention to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which obviate the current practice of venting the pressurized gas to a stock tank. It is a further object of this invention to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which capture the pressurized gas above the plunger for sale. Yet another object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which provide for conservation of the natural resource and obviate the release of pollutants into the atmosphere. A further object of this invention is to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which improve efficiency of plunger lift wells, extend productive well life and recover additional reserves. And it is an object of this invention to provide a system and process for reducing the flowing bottom hole pressure of a natural gas well which improve the tandem performance of plunger lift equipment and onsite lease compression.
In accordance with the invention, a process and system are provided for use in natural gas production operations which separate natural gas and produced liquids under positive and/or negative pressures without use of pressure created by the natural gas flow stream and/or back pressure which is naturally or artificially created or maintained to transfer collected fluids during periods of natural gas flow. The process and system contemplate use of a vessel equipped with an inlet for receipt of the producing stream, an outlet for discharge of processed gas, storage capacity for retention of produced liquids and a liquid discharge outlet which may be equipped with a xe2x80x9cdumpxe2x80x9d valve in association with a liquid level device.
Liquids may be transferred from this vessel to and/or for processing, use, sale, storage, transport, discharge, disposal or other purposes by a pump which may operate while the vessel is actively processing a natural gas flow stream or during periods when the vessel or portion of the vessel is effectively isolated from the natural gas flow stream. This may or may not include the use of any liquid level monitoring apparatus. A liquid level device such as a float may be combined with the liquid dump valve to regulate fluid discharge and reduce or eliminate the incidental transfer of natural gas with the produced liquid. The pump would be capable of developing a positive discharge pressure while transferring liquid from the vessel operating at near or less than atmospheric conditions. Any known power source can be used for the pump, such as an electric motor, a natural gas combustion engine or hydraulic and/or natural gas pressure.
Liquids may alternately be transferred from or to the vessel for processing, use, sale, storage, transport, discharge, disposal or other purpose by subjecting the vessel to either a positive or negative pressure during periods when the vessel is effectively isolated from the natural gas flow stream.
Such transfers of collected fluids will not cause an increase in the flowing pressure of the natural gas stream. This process is designed for continuous and/or intermittent flow processing conditions. Intermittent flow processing utilizes one vessel and continuous flow processing may utilize one vessel or may utilize two vessels installed in parallel flow paths.
The process and system can be used with or without the aid of wellhead compression for natural gas wells flowing gas and liquid continuously or intermittently through surface equipment, for natural gas wells with a plunger lift intermittently flowing gas and liquid through surface equipment, or for oil or gas wells with an artificial lift flowing gas and liquid from the casing through surface equipment.
In a preferred application of the process, a discrete fluid flow path is provided from the surface well head through a valve to an inlet of a separator and a discrete gas flow path is provided from an outlet of the separator to an inlet of a compressor. The compressor is operated to maintain a near or below zero PSIG pressure at the separator inlet and the valve is opened to reduce the pressure at the well head.
When the process is used to remove a fluid column of liquid and gas loading a plunger in a production line of a gas well having a positive downhole pressure, the discrete fluid flow path is provided from a well head end of the production line through a valve to an inlet of a separator and the discrete gas flow path is provided from an outlet of the separator to an inlet of a compressor. The compressor is operated to maintain a pressure near or below zero PSIG at the separator inlet. A flow line valve is normally closed to build bottom hole pressure. The valve is opened to allow the plunger to rise in the tubing and convey the fluid column along the fluid flow path into the separator.
The compressor continues operating to maintain a near or below zero PSIG pressure at the separator inlet to convey the gas along the gas flow path from the separator to the compressor.
In a preferred embodiment of the system, a first discrete fluid flow path extends from the well head outlet through a valve to an inlet of a separator, the valve being actuable between a closed condition and an open condition, and a second discrete gas flow path extends from an outlet of the separator to an inlet of a compressor, the compressor maintaining a pressure near or below zero PSIG at the separator inlet.
When the valve is in the closed condition, positive pressure builds on the well head side of the valve and, when the valve is in the open condition, the pressure near or below zero PSIG of the separator is applied to the well head. In applications for receiving a fluid column of gas and liquid loading a plunger in the tubing of a natural gas well, when pressure near or below zero PSIG is applied to the well head, the fluid column is transferred along the fluid flow path into the separator and the gas is transferred along the gas flow path from the separator to the compressor.